1. Field of the Invention
This invention relates to a process for the treatment of industrial effluent gases, and, more specifically, this invention relates to a process for the removal of carbon dioxide (CO2), nitrogen oxides (NOx), and sulfur dioxide (SO2), as generated from sources such as power plants that utilize fossil fuel.
2. Background of the Invention
Uncontrolled acid anhydride gases in flue gas produced by the combustion of fossil fuels have long been a cause of acid-rain-related air pollution problems. The acid anhydride precursor gases which cause the most serious problems are sulfur dioxide (SO2) and nitrogen oxides (NOx). (Sulfur dioxide and NO are precursors to sulfur trioxide (SO3) and nitrogen dioxide (NO2)). Another acid anhydride precursor gas caused by fossil fuel combustion is carbon dioxide (CO2) which can cause global climate change or the “greenhouse effect.” Carbon dioxide can exist in flue gases at concentrations hundred of times higher than the combined concentrations of SO2 and NOx.
Methods to prevent these acid anhydride gases from entering the atmosphere are technically complex and very costly, especially if each acid gas is to be removed by a different technology. For example, limestone slurry (calcium carbonate, CaCO3) scrubbing can be used for SO2 removal with subsequent selective catalytic reduction (SCR) for NOx reduction and a wet scrubbing amine process (e.g., monoethanolamine, MEA) for CO2 capture.
Amine-Based CO2 Absorption Technologies
Absorption processes using aqueous amine solutions have been used to remove CO2 from gas streams in some industries. These processes often are referred to as wet chemical scrubbing.
Wet chemical scrubbing of CO2 involves one or more reversible chemical reactions between CO2 and amine substances in aqueous solutions of monoethanolamine (MEA) or diethanolamine (DEA) to produce a liquid species, such as a carbamate. Upon heating, the carbamate breaks down to free CO2, with the original amine regenerated to react with additional CO2. An example of the process, with MEA, is given by Equation 1:
                                          2            ⁢                                                  ⁢                          RNH              2                                +                      CO            2                          ⁢                  ↔          hot          cold                ⁢                              RNH            3                    ⁢          COOHNR                                    Equation        ⁢                                  ⁢        1            for which the two moieties represented by R may be either any alkyl moiety, any aryl moiety, or any combination thereof. At high CO2 concentrations, bicarbonate formation may also take place.
Typically, these amines, MEA and DEA, are used as 15 to 30 wt. % amine in aqueous solution. The amine solution enters the top of an absorption tower while the carbon dioxide containing gaseous stream is introduced at the bottom. During contact with the CO2-containing gaseous stream, the amine solution chemically absorbs the CO2 from the gaseous stream to create a carbamate. Conversion of carbamate ions back to CO2 proceeds through a thermal regeneration process, typically at a temperature of about 120° C. Carbon dioxide and water emerge from the amine solution and the water is separated via condensation using a heat exchanger. After regeneration, the amine solution is recycled back to the absorption tower for additional CO2 absorption.
Carbon dioxide capture and regeneration in the above-described manner require high temperatures or very low vacuum. Regeneration of CO2 from MEA solution may use up to 80% of the total energy consumed in the CO2 absorption and regeneration cycle. As such, the process outlined supra is energy intensive. Further, the amine solution has a limited lifetime due to degradation through oxidation of the amine. In addition, high amine concentrations and high CO2 loadings exacerbate corrosion problems of process equipment.
MEA systems require that SO2 be removed first from flue gas streams, otherwise, MEA is degraded by SO2 and oxygen (O2), forming irreversible products. Specifically, if the SO2 is not removed, amines combine with SO2 in flue gases from coal-burning power plants to produce insoluble salts. The insoluble salts cannot be regenerated by thermal decomposition. Thus, the insoluble salt must be disposed of at a considerable cost. Also, the amine solvents such as MEA must be replenished because part of it forms the waste-byproduct along with SO2.
NOx must also be eventually removed from the flue gas before it is discharged into the air in order to meet present and future gaseous emission limits. NOx nominally consists of approximately 95% NO (nitric oxide) and 5% NO2 (nitrogen dioxide). NOx removal occurs upstream of the CO2 absorber and is accomplished by low NOx burners and/or selective catalytic reduction.
Current Ammonia-Based SO2 Absorption Technologies
Commercial processes exist that contact environmental flue gases with gaseous ammonia to remove sulfur oxides. Ammonium bisulfite is formed with subsequent oxidation to ammonium bisulfate, and eventual neutralization of the bisulfate with water and ammonia to form ammonium sulfate.
Other processes contact combustion or flue gases containing sulfur oxides with solutions of ammonium sulfate/sulfite, and in one instance, the resulting solution is reacted with H2S to form ammonium thiosulfate. These aqueous-based processes do not remove nitrogen oxides, primarily because the more abundant nitric oxide has a limited solubility in water.
One commercial process uses ammonia to simultaneously remove SO2 and NOx within one reactor and produce mixed ammonium sulfate and nitrate fertilizer. This process is described in R. R. Lunt and J. D. Curic, Profiles in Flue Gas Desulfurization, 76-77, American Institute of Chemical Engineers (2000). Flue gas is first partially saturated and cooled with water to a temperature of 150°±10° F. The flue gas is subsequently mixed with ammonia and passed to the reactor where the flue gas-ammonia mixture is subjected to beams of high energy electrons to oxidize the sulfur dioxide and NOx. These oxidized species subsequently react with the ammonia to form ammonium sulfate and ammonium nitrate particulate. This process does not address the greenhouse gas (CO2) capture and removal problem. Further, the process gives an undesirable trace byproduct, ammonium sulfamate, which is harmful to crops. Finally, the process is expensive.
Studies demonstrate the efficacy of a wet ammonia scrubbing process for the removal of carbon dioxide from flue gases. A. C. Yeh and H. Bai, “Comparison of Ammonia and Monoethanolamine Solvents to reduce CO2 Greenhouse Gas Emissions,” The Science of the Total Environment, 228, 121-133 (1999), and H. Bai and A. C. Yeh, “Removal of CO2 Greenhouse Gas by Ammonia Scrubbing,” Ind. Eng. Chem. Res., 36(6), 2490-2493 (1997). The CO2 regeneration step in this process requires no more than 20% of the energy necessary for the CO2 regeneration step in MEA-based processes. Further, the regeneration temperature (60° C.) in this wet scrubbing process is half that required in MEA systems.
The Krupp Koppers process uses ammonia (NH3) solution in a wet scrubber to remove SO2 from flue gas. However, inasmuch as NO is not soluble in ammonia solution (NO must be oxidized to NO2 to become soluble in ammonia solution), NO is removed by a second process in a second reactor, which is called Selective Catalytic Reduction (SCR). The SCR process is energy-intensive because the flue gas must be reheated to 300° C. This process is described in W. Schulte, “Flue Gas Cleaning With Ammonia Reduces SO2 and NOx Emissions,” Thirteenth International Pittsburgh Coal Conference Proceedings, Sep. 3-7, 1996, Pittsburgh, Pa.
The Marsulex process is similar to the Krupp Koppers process in that Marsulex focuses on SO2 removal using ammonia in a wet scrubber. However, the Marsulex process does not address CO2 and NOx capture and removal from flue gases. This process is described in M. A. Walsh, Jr., “New Marsulex Technology Significantly Cuts Power Generation Costs,” Corporate Publication (2000).
Gas-phase oxidation of nitric oxide (NO) to water-soluble nitrogen dioxide (NO2) can be accomplished by strong oxidizing agents such as hydrogen peroxide (H2O2), ozone (O3), and chlorine dioxide (ClO2). Hydrogen peroxide-enhanced gas phase oxidation of nitric oxide has been demonstrated. J. M. Kasper, C. A. Clausen III, and D. C. Cooper, “Control of Nitrogen Oxide Emissions by Hydrogen Peroxide-Enhanced Gas-Phase Oxidation of Nitric Oxide,” Air & Waste Manage. Assoc., 46(2) 127-133 (1996).
U.S. Pat. Nos. 6,416,722 and 6,355,084 awarded to Izutsu, et al. on Jul. 9, 2002 and Mar. 12, 2002, respectively, disclose a method for desulfurizing gases by contacting sulfur oxides with gaseous ammonia with subsequent electron beam irradiation.
U.S. Pat. No. 6,221,324 awarded to Coq, et al. on Apr. 24, 2001 discloses a method for the removal of nitrogen oxides from waste streams by selective catalytic reduction contacting the waste gaseous stream with ammonia over zeolite catalysts.
U.S. Pat. No. 6,197,268 awarded to Hwang, et al. on Mar. 6, 2001 discloses a method for the removal of nitrogen oxides from waste streams by contacting the waste gaseous stream with gaseous ammonia.
U.S. Pat. No. 5,648,053 awarded to Mimura, et al. on Jul. 15, 1997 discloses a method for the removal of both carbon dioxide and nitrogen oxides from combustion or flue gases by contacting the gaseous stream, after oxidation treatment, with an alcohol amine.
U.S. Pat. No. 5,512,097 awarded to Emmer on Apr. 30, 1996 discloses a method for the removal of sulfur oxides from waste streams by contacting the waste gaseous stream with an aqueous slurry of finely comminuted limestone.
U.S. Pat. No. 5,510,094 awarded to Bhat, et al. on Apr. 23, 1996 discloses a method for the removal of sulfur oxides from waste streams by contacting the waste gaseous stream with oxidants. Subsequent to oxidation, the gaseous stream is contacted with an aqueous slurry of limestone and gaseous ammonia in a scrubber tower.
U.S. Pat. No. 5,176,088 awarded to Amrhein, et al. on Jan. 5, 1993 discloses a device and method for the simultaneous removal of nitrogen oxides and sulfur oxides from furnace exhausts. Injections of limestone, then ammonia are made into the furnace with subsequent contacting of the furnace waste stream with ammonia and calcium sorbent in a dry scrubber for additional sulfur oxides removal.
U.S. Pat. No. 4,426,364 awarded to Cooper on Jan. 17, 1984 discloses a method for removing nitrogen oxides from gases, after oxidation treatment, by contacting the gases with a bicarbonate/carbonate aqueous solution.
U.S. Pat. No. 4,251,496 awarded to Longo, et al. on Feb. 17, 1981 discloses a method for removing sulfur oxides and nitrogen oxides by first contacting the gaseous mixture with cerium oxide to remove sulfur oxides, then contacting the gaseous mixture with gaseous ammonia to remove nitrogen oxides.
None of the aforementioned patents or papers disclose any efficacious method or process for the simultaneous removal of a plurality of gaseous acid anhydrides and acid halides from combustion or flue gases. In addition, the state of the art does not disclose an aqua ammonia scrubbing process for gaseous acid anhydrides and gaseous acid halides. None of the aforementioned patents, papers, and processes address the potential capture and removal of greenhouse gases (CO2), together with removal of SO2 and NOx.
A need exists in the art for a method and device to remove all environmental gases, including CO2, from flue gases without producing any harmful byproducts. The method should be an aqueous-based ammonia scrubbing method and device to facilitate the removal of gaseous acid anhydrides, including nitric oxide, and acid halides from combustion or flue gases. Finally, the method and device should have low energy usage to minimize costs.